Once a shale gas condensate reservoir is produced, the reservoir pressure falls below the dew-point pressure, and the condensate liquid will be formed in the pore space; the condensate can then accumulate near the wellbore. This condensate blockage would reduce the gas relative permeability and decrease the gas production. The condensate is formed by the heavy components in reservoir fluid, and these heavy componenets are very valuable economically in the industry. Therefore, operators are seeking ways to maximize condensate recovery from gas-condensate reservoirs.
Huff-n-puff gas injection is an effective approach for enhancing condensate recovery in shale gas condensate reservoirs, as shown by our earlier papers (
In this experimental study, a binary gas condensate mixture was used to investigate the dominant mechanism. The core was saturated with a gas condensate mixture at 2200 psi to simulate the initial reservoir condition. Then, the pressure was depleted to 1500 psi, which was lower than the dew point pressure. During the depletion, the produced gas was collected in a vacuumed gas sample bag. After depletion, the huff-n-puff method was applied. After every cycle of huff-n-puff, the produced gas was collected. GC was used to analyze the compositions of the different gas samples. Also, a CT scanner was used to determine the condensate saturation in the core. From the GC analysis, by comparing the gas sample after primary depletion with the gas sample after the first cycle, it was found that the heavy component-butane increased significantly. This means that most of the heavy components of condensate were revaporized and flew out with the dry gas. This proves the revaporization mechanism of the huff-n-puff gas injection.
Our experiment results show that huff-n-puff was an effective way to enhance the condensate recovery, and revaporization was the main mechanism of huff-n-puff. When the pressure was increased in the huff process, the heavy components were revaporized and flowed out with gas in the puff process. Though in the gas flooding method, the reservoir pressure was also increased, but the near-wellbore pressure was not increased very much in the shale gas reservoirs; thus, heavy components would still be formed near the wellbore. However, in the huff-n-puff method, because of the same well, the pressure near the wellbore would be higher than the dew point pressure in the beginning of production process. Therefore, the heavy component would be recovered with gas. Our GC results visually showed the revaporization mechanism of huff-n-puff in the shale gas condensate.
Suarez, Ricardo G. Suarez (SPE University of Calgary) | Scott, Carlos E. (SPE University of Calgary) | Pereira-Almao, Pedro (SPE University of Calgary) | Hejazi, S. Hossein (SPE University of Calgary)
Nanocatalytic in-situ upgrading is a novel oil recovery method that involves chemical, thermal and miscible processes. In this work the main oil recovery mechanisms of nanocatalytic in-situ upgrading were studied, particularly the ones that promote additional oil production from low matrix permeability blocks.
Heavy oil recovery from Silurian dolomite cores was studied using a cylindrical core holder set-up. Fractures in the system were represented by a gap between the core sample and core holder wall. Oil recovery experiments were conducted in batch-mode using hydrogen and a trimetallic nano-catalyst. The cores were fully saturated with heavy-oil and the fractures were filled with hydrogen and vacuum residue with ultra-dispersed nano-catalyst at 300 °C and 1000 psig. The produced oil from the matrix was collected and the recovery factor for each experiment was calculated. Moreover, the residual oil in the core was extracted using a solvent. Both samples (i.e., produced and residual oil) were characterised by laboratory measurements and analytical techniques in order to assess oil quality distribution.
Experimental results revealed a significant increment in oil recovery with hydrogen injection. This increment suggests that during nanocatalytic in-situ upgrading oil is produced due to the presence of hydrogen in gas form. Results also demonstrated that, by use of an ultra-dispersed Ni-W-Mo nano-catalyst, the oils contained in both the fracture and matrix, were upgraded.
This research fosters the understanding of the main recovery mechanisms from carbonate matrix blocks by use of nanocatalytic in-situ upgrading. This study contributes to better understanding a recovery technique that will unlock heavy-oil resources contained in carbonate rocks.
Thrasher, David (BP Exploration) | Nottingham, Derek (BP Exploration (Alaska) Inc.) | Stechauner, Bernhard (BP Exploration (Alaska) Inc.) | Ohms, Danielle (BP Exploration (Alaska) Inc.) | Stechauner, Gerda (BP Exploration (Alaska) Inc.) | Singh, Praveen K. (BP America Inc.) | Angarita, Monica Lara (BP Exploration)
Waterflood conformance control due to reservoir heterogeneity is a common challenge to many oilfield developments. This paper describes the application at-scale of a thermally-activated polymer particle system (TAP) for improving waterflood sweep efficiency in the Prudhoe Bay field, Alaska. Since 2004, the technology has been successfully deployed 91 times in Prudhoe Bay Unit on the North Slope of Alaska as part of an approved Enhanced Oil Recovery (EOR) program. A total of 1.6 million gallons of chemical polymer particles have been injected into approximately half of the available waterflood patterns.
Once the polymer particles activate deep in the reservoir, they provide resistance to water flow in the thief (swept) zones. The treatment design workflow applies a thermal model which accounts for the impact of the temperature distribution in the reservoir on activation of the polymer particles. Challenges associated with performance evaluation of the treatment program in a normal operational setting (as opposed to field trial) have been addressed, particularly in relation to interferences to interpretation resulting from the ongoing application of miscible gas EOR in the waterflood areas.
Of the 44 treatments deployed between 2008 and 2012, 22 were sufficiently mature to have performance data which was not adversely impacted by interferences from well work, changes to operating conditions, or miscible gas breakthrough. So far, only one of the 22 patterns has not indicated an incremental oil response, while in two patterns the response had started too recently to be able to extrapolate the overall response magnitude. The analysis showed overall positive responses from the treatments that are competitive with other well work on cost/bbl and project economics. Results from this study provide insights on key controls on waterflood sweep improvements, and inform future candidate selection and optimization of treatment designs.
The production performance analysis was corroborated by wellhead injectivity, repeat pressure fall-off tests, and reservoir modeling. This paper documents a good case history of waterflood sweep improvement.
Production from liquid-rich shale has become an important contributor to domestic production in the United States, but recovery factors are low. Enhanced Oil Recovery (EOR) methods require injectivity and interwell communication on reasonable time scales. We conduct a feasibility study for the application of recycled lean gas injection to displace reservoir fluids between zipper fracs in liquid-rich shales.
Using new analytical solutions to the Diffusivity equation for arbitrarily-oriented line sources/sinks plus superposition, we analyze the time for inter-fracture communication development, i.e. interference, and productivity index for both classical bi-wing fractures in a zipper configuration and complex fracture networks. We are able to map both pressure and pressure temporal derivative as a function of time and space for production and/or injection from parallel motherbores under the infinite conductivity wellbore and fracture assumption. The infinite conductivity assumption could be later relaxed for more general cases.
We couch the results in terms of geometrical spacing requirement for both horizontal wells and stimulation treatments to achieve reasonable time frames for inter-fracture communication and sweep for parameters typical of various shale plays. We further analyze whether spacing currently considered for primary production is sufficient for direct implementation of EOR or if current practice should be modified with EOR in the field development plan.
This paper summarizes the current state of the ethane industry in the United States and explores the opportunity for using ethane for enhanced oil recovery. We show both simulation data and field examples to demonstrate that ethane is an excellent EOR injectant.
After decades of research and field application, the use of CO2 as an EOR injectant has proven to be very successful. However, there are limited supplies of low cost CO2 available, and there are also significant drawbacks, especially corrosion, involving its use. The rich gasses and volatile oils developed by horizontal drilling and fracturing in the shale reservoirs have brought about an enormous increase in ethane production. Ethane prices have dropped substantially. In the U.S., ethane is no longer priced as a petrochemical feedstock, but is priced as fuel. Also, substantial quantities of ethane are currently being flared.
Ethane-based EOR can supplement the very successful CO2-based EOR industry in the U.S. There simply isn't enough low-cost CO2 available to undertake all of the potential gas EOR projects in the U.S. The current abundance of low-cost ethane presents a significant opportunity to add new gas EOR projects. The ethane-based EOR opportunity can be summarized as follows; CO2-based EOR works well, and is well understood. Ethane is better than CO2 for EOR. Ethane is simpler than CO2 for EOR. Ethane is now inexpensive, and will likely stay inexpensive. Ethane-based EOR has become a viable option in the Lower 48. Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.
CO2-based EOR works well, and is well understood.
Ethane is better than CO2 for EOR.
Ethane is simpler than CO2 for EOR.
Ethane is now inexpensive, and will likely stay inexpensive.
Ethane-based EOR has become a viable option in the Lower 48. Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.
In this paper, we estimate foam parameters and investigate foam behavior for a given range of water saturation using two local equilibrium foam models: the population balance and the Pc*. Our method uses an optimization algorithm to estimate foam model parameters by matching foam measured pressure gradient from steady-state coreflood experiments. We calculate the effective foam viscosity and the water fractional flow using experimental data and we then compare lab data against results obtained with the matched foam models to verify the foam parameters. Other variables, such as the foam texture and foam relative permeability are used to further investigate the behavior of the foam during each experiment. We propose an improvement to the Pc* model with a better match in high quality regime by assuming resistance factor and critical water saturation is a linear function of pressure gradient. Results show that the parameter estimation method coupled with an optimization algorithm successfully matches the experimental data using both foam models. In the population balance, we observe different values of the foam effective viscosity for each pressure gradient due to variations of the foam texture and shear thinning viscosity effect. The Pc* model presents a constant effective viscosity for each pressure gradient; we propose the use of resistance factor and critical water saturation as a linear function of pressure to improve the match in the high quality regime, when applicable. Foam has been successfully used in the oil industry for conformance and mobility control in gas injection processes. The efficiency of a foam injection project must be assessed by means of numerical models. Although there are several foam flow models in the literature, the prediction of foam behavior is an important issue that needs further investigation.
As one of the unconventional resources, tight oil has become one of the most important contributor of oil reserves and production growth. The successful commercial production of tight oil is mainly reliant on the advancement in horizontal drilling and multistage hydraulic fracturing technique. Development of tight oil reservoirs remains in an early stage. Primary oil recovery factor in these reservoirs is very low, leaving substantial volume of oil trapped underground due to the low porosity, low permeability characteristic of tight oil reservoirs. Thus, investigation of enhanced oil recovery methods is more than imperative in tight oil reservoirs. CO2 Huff-and-Puff technology has been effectively applied in conventional reservoirs and can be tailored to adapt for the characteristics of tight oil reservoirs.
In this study, the performance of water flooding in tight oil reservoir is studied and compared with that of the CO2 Huff-and-Puff process. Sensitivity analysis demonstrates that the performance of CO2 Huff-and-Puff is more sensitive to the length of gas injection and production step in each cycle, compared to the soaking time. The CO2 Huff-and-Puff process is optimized and an adaptive CO2 Huff-and-Puff process is conducted for tight oil reservoirs after primary production. Simulation results show that the adaptive cycle length CO2 Huff-and-Puff process can improve the incremental oil recovery by 11.1% over a fixed cycle length process. Finally, the inter-well interference during CO2 Huff-and-Puff is studied, and it is found that a multi-well asynchronous CO2 Huff-and-Puff pattern can improve the incremental oil recovery by 31.6% over that of a synchronous pattern.
Al Ayesh, A. H. (Department of Geoscience and Engineering, Delft University of Technology) | Salazar, R. (Department of Geoscience and Engineering, Delft University of Technology) | Farajzadeh, R. | Vincent-Bonnieu, S. | Rossen, W. R.
Foam can divert flow from higherto lower-permeability layers and thereby improve vertical conformance in gas-injection enhanced oil recovery. Recently,
The effectiveness of diversion varies greatly with injection method. In a SAG (surfactant-alternating-gas) process, diversion of the first slug of gas depends on foam behavior at very high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This of course favors diversion away from high-permeability layers that receive a large surfactant slug, but there is an optimum surfactant slug size: too little surfactant and diversion from high-permeability layers is not effective; too much and mobility is reduced in low-permeability layers, too. For a SAG process, it is very important to determine if foam collapses completely at irreducible water saturation.
In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with time of injection. Injectivity is extremely poor with foam injection, but is not necessarily worse than waterflood in some effective SAG foam processes
Rodriguez, F. (PDVSA, IFP Energies nouvelles, Paris Diderot University) | Rousseau, D. (IFP Energies nouvelles) | Bekri, S. (IFP Energies nouvelles) | Hocine, S. (Solvay) | Degre, G. (Solvay) | Djabourov, M. (ESPCI Paris Tech) | Bejarano, C. A. (PDVSA)
Primary cold production for the extra-heavy oils (4–10°API) of La Faja Petrolifera del Orinoco (FPO), Venezuela, is currently a low percentage (<5%) of the OOIP. Chemical EOR (CEOR) studies are being accomplished in order to increase oil recovery in those thin-bedded reservoirs which host up to 35% of the OOIP, where thermal EOR methods are not convenient because of heat losses and environmental issues. Specifically, Surfactant-Polymer (SP) flooding is now considered as a feasible approach to achieve both mobility control and mobilization of residual oil in the FPO's target zones for CEOR.
The objectives of this experimental study were to identify some mechanisms in play when surfactant and polymer solutions are injected in cores to displace extra-heavy oil and to assess for the potential of SP flooding for one of the FPO's reservoirs. The tests reported were performed with a dead crude oil of 9°API and 4500 cP, and injection water salinity of 6.4 g/L with low hardness and at a temperature of 50°C. The SP formulation consisted of a standard high molecular weight HPAM at rather high concentration to achieve high viscosity and an alkaline-free surfactant formulation providing both low interfacial tension (IFT) and good compatibility with polymer even at high polymer concentration. When possible, oil saturation profiles were determined by CT-scan at the main steps of the experiments.
Conditions and methodologies to determine the relevant experimental parameters for high viscosity oil have firstly been developed. Then, a set of surfactant and polymer injection tests have been performed on Bentheimer outcrop cores. These tests demonstrated that injection of the SP formulation after a secondary polymer flood was able to achieve a significant reduction of the residual oil (ASo = 80% ROIP). Results of secondary injections of water (final oil saturation, Sofinal = 63%), surfactant solution (Sofinal = 39%) and SP formulation (Sofinal = 5%) have also shown that mobility control is of tremendous importance to achieve high recovery, even at the core-scale. The potential of the SP formulation has also been validated on unconsolidated reservoir rock material from the FPO (Sofinal = 8%). Relative permeabilities have also been determined to investigate the feasibility of an effective modeling of the impact of the surfactant on oil recovery without making any assumption of the local mechanisms in play. Future work will involve 3D reservoir simulation with physico-chemical parameters generated at the lab.
Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high salinity brines, so it is advantageous to inject low salinity water as a preflush. Low salinity water flooding (LSW) can also improve local displacement efficiency by changing the wettability of the reservoir rock from oil wet to more water wet. The mechanism for wettability alteration for low salinity waterflooding in sandstones is not very well understood, however experiments and field studies strongly support that cation exchange (CE) reactions are the key element in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport has not been explained to date.
This paper presents the first analytical solutions for the coupled synergistic behavior of low salinity waterflooding and polymer flooding considering cation exchange reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the cation exchange of Ca2+, Mg2+ and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase flow and reactive transport model is decoupled into three simpler sub-problems, one where cation exchange reactions are solved, the second where a variable polymer concentration can be added to the reaction path and the third where fractional flows can be mapped onto the fixed cation and polymer concentration paths. The solutions are used to develop a front tracking algorithm, which can solve the slug injection problem where low salinity water is injected as a preflush followed by polymer. The results are verified with experimental data and PennSim, a general purpose compositional simulator.
The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low salinity pre-flush prior to polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned LSP flood can be as much as 10% OOIP greater than with considering polymer alone. The results show the structure of the solutions, and in particular the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in core floods for small low salinity slug sizes are explained with intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP as a cheaper and more effective way for performing polymer flooding when the reservoir wettability can be altered using chemically-tuned low salinity brine.